Steam stimulation recovery techniques are widely used to increase production from an oil bearing formation. In steam stimulation techniques, steam is used to heat the section of a formation adjacent to a wellbore so that production rates are increaesd through lowered oil viscosities and the corresponding reduced resistance to flow through the injected area.
In a typical conventional steam stimulation injection cycle, steam is injected into the desired section of a reservoir. A shut-in or "soak" phase may follow, in which thermal energy diffuses through the formation. A production phase follows in which oil is produced until oil production rates decreases to an uneconomical amount. Subsequent injection cycles are often used to increase recovery.
Steam stimulation techniques recover oil at rates as high as 80-85% of the original oil in place in zones in which the steam contacts the reservoir. However, there are problems in contacting all zones of a reservoir due to heterogeneities in the reservoir such as high/low permeability streaks, which may cause gravity override, and steam fingering. When any of these heterogeneities are present in a reservoir, the efficiency of the process begins to deteriorate due to reduced reservoir pressure, reservoir reheating, longer production cycles, and reduced oil-steam ratios. As a result, steam stimulation may become unprofitable.
Various methods have been proposed so that steam can be diverted to uncontacted zones of a reservoir. One such method is disclosed in U.S. Pat. No. 2,402,588 issued to Andresen ("Andresen"). Andresen discloses a method of sealing a more permeable area of a reservoir by injecting into a reservoir a dilute alkaline solution of sodium silicate under low pressure. An acid gas such as carbon dioxide is then injected to reduce the alkalinity of the solution, resulting in gelling.
Another method is disclosed in U.S. Pat. No. 3,645,336 issued to Young et al. ("Young"). Young discloses the plugging of a zone of a reservoir by injecting a mixture of steam and sodium silicate into the permeable zone. A second mixture containing steam and a gelling agent such as carbon dioxide is injected in the permeable zone, and the two mixtures are allowed to react. A hard silica gel plug is formed.
Yet another method is disclosed in U.S. Pat. No. 3,805,893 to Sarem ("Sarem"). Sarem discloses the formation of a gelatinous precipitate by injection of small slugs of a dilute aqueous alkaline metal silicate solution, followed by water and then a dilute aquenous solution of a water soluble material which reacts with the alkali metal silicate to form a precipitate. The precipitate hardens to form a substantially impermeable substance.
U.S. Pat. No. 3,965,986 issued to Christopher ("Christopher") discloses still another method. In Christopher, a slug of fumed colloidal silica and water is injected into a reservoir. This slug has a relatively low viscosity. A surfactant is then injected which forms a gel on contact with the silica slug.
Meyers et al. ("Meyers") disclosed a method for reducing the permeability of a subterranean formation in U.S. Pat. No. 4,676,318. Here an alkali metal silicate foam was produced by injecting into the formation a solution of alkali metal silicate, a chemical surfactant, and a non-condensible gas. The foam hardens into a substantially impermeable solid. The foam may be used to reduce permeability in areas of the formation which have been steam swept during steam stimulation cycles. Thus, subsequent steam stimulation cycles were directed to uncontacted areas of the formation.
In each of the above methods the gas required for forming the foam was injected into the formation. Therefore, what is required is a method whereby a foam can be generated by a gas released in-situ.